New Discoveries, Cost Reductions Spur Deepwater Interest

A series of recent deepwater discoveries has demonstrated that the offshore oil sector is beginning to rebound after years of subdued activity, despite increasing interest in onshore shale drilling. The oil majors have shelved long-term conventional projects, cut spending, and diversified into short-cycle U.S. shale over the last few years, but they have not abandoned conventional large-scale offshore drilling altogether. Now, with oil prices stronger than during the previous few years and drilling costs lower, interest in offshore exploration is rising.

New discoveries, renewed interest

On January 31, Royal Dutch Shell announced one of its largest discoveries in the Gulf of Mexico in the past decade. Shell’s “Whale” deepwater well, in which Chevron owns a 40 percent stake, still needs to be appraised, but the oil majors are enthusiastic about it. The discovery is located only 10 miles from Shell’s large Perdido platform in the Gulf of Mexico, and it is also immediately adjacent to Shell’s Silvertip field. Meanwhile, Shell has three other Gulf of Mexico projects under construction—Appotmattox, Kaikias, and Coulomb Phase 2.

Also on January 31, BP announced two discoveries in the North Sea—the Capercaillie in the Central North Sea and the Achmelvich west of Shetland. “These are exciting times for BP in the North Sea as we lay the foundations of a refreshed and revitalized business that we expect to double production to 200,000 barrels a day by 2020 and keep producing beyond 2050,” BP North Sea Regional President, Mark Thomas, said in a statement.

“These are exciting times for BP in the North Sea as we lay the foundations of a refreshed and revitalized business.”

On the same day, Shell picked up nine blocks in Mexico’s deepwater auction, adding to its position just across the maritime border in U.S. waters. Shell acquired four blocks on its own, one in conjunction with state-owned Pemex, and four with Qatar Petroleum International Limited. Shell is the lead operator on all nine. That came after Shell had positive results in Brazil’s offshore auction late last year, the first auction of the country’s prolific pre-salt fields after a major legislative overhaul that allowed greater participation from international firms.

Moreover, along with partnering in Shell’s recent Whale discovery, Chevron recorded its own discovery a day earlier. Chevron, joining French oil giant Total SA, announced the discovery of the Ballymore prospect in the Gulf of Mexico. This project is also located near existing operations—Ballymore is just three miles from Chevron’s Blind Faith platform.

The proximity to existing operations will improve the economics of the projects, increasing the chances that they receive final investment decisions.

The proximity to existing operations will improve the economics of the projects, increasing the chances that they receive final investment decisions and move forward on development. To a large extent, that is true for much of the Gulf of Mexico, a region with a heavy drilling presence offshore and extensive pipelines, processing facilities, and refineries onshore. In one recent example, BP’s Constellation project in the Gulf of Mexico found oil that would be unprofitable if developed from scratch. Instead, the oil major partnered with Anadarko, which had infrastructure nearby, and tied back the project to Anadarko’s operations 30 miles away, a development that allowed the project to move forward.

Higher prices, lower costs

The raft of announcements within days of each other was, in part, a bit of unplanned timing. Still, exploration and investment are starting to rise modestly, after years of subdued activity. An uptick in oil prices along with ongoing efforts at cutting exploration and development costs are allowing a rebound to occur in the offshore sector.

Production in the Gulf of Mexico, for instance, could hit 1.9 million barrels per day (Mbd) this year, according to Wood Mackenzie, up from 1.4 Mbd in 2014. While much of the output gains in recent years can be attributed to projects that were given FIDs before the 2014 oil price downturn, new projects are also moving forward in an environment in which WTI trades between $50 and $60 per barrel. In fact, some companies are taking advantage of the cyclical downturn and deflation in drilling costs to greenlight new large-scale projects.

Production in the Gulf of Mexico could hit 1.9 Mbd this year, up from 1.4 Mbd in 2014.

In late 2016, for example, BP sanctioned the Mad Dog 2 project after slashing projected development costs by more than half to $9 billion. BP brought seven major projects online in 2017, and has an additional six queued up for 2018. The British oil giant is expected to add 900,000 barrels of oil equivalent per day (boe/d) between 2016 and 2021.

“There is certainly exploration activity taking place worldwide,” said Pavel Molchanov, an energy analyst with Raymond James, according to the Houston Chronicle. “Even at $55 oil, that’s still a price that supports a fair amount of exploration activity. At $30, nobody does any exploration.”

The industry is also at the beginning of the next phase of cost reductions through the use of Big Data, automation, robotics, and other innovative technologies, all of which is beginning to translate into cost savings. The impact of this new wave of energy digitalization is still unknown—the most bullish forecasts say a 40 percent reduction in costs, while the IEA pegs the figure at a more modest 10-20 percent. Much of the automation may occur in onshore shale drilling, but the ability to crunch massive reams of data will aid offshore development. For example, Eni discovered the Zohr natural gas field off the Egyptian coast in 2015. With the help of the third most powerful supercomputer in the industry, Eni fast-tracked development and brought it online in record time at the end of 2017.

“The potential for advanced digital capabilities to improve deepwater competitiveness and productivity are monumental,” William Turner, senior research analyst for Wood Mackenzie, told Hart Energy in January. “In 2018, the industry will finally begin to widely embrace and implement buzzwords like internet of things, automation and big data to achieve new and sustainable efficiencies and optimizations that decrease unplanned downtime, improve maintenance processes, extend asset and equipment life and reduce costs.”

However, any rebound in drilling and offshore spending will be growing from a base that is substantially lower than just a few years ago. Total upstream capital and exploration spending hit a peak at $900 billion in 2014, according to Rystad Energy. The Oslo-based consultancy predicts spending will bottom out this year at $510 billion before rising again. But spending is not expected to return to 2014 levels until 2025. Some analysts have argued that without increased deepwater exploration and production, a supply gap may emerge next decade as long as demand continues to grow at its current pace.

Some analysts have argued that without increased deepwater exploration and production, a supply gap may emerge next decade.

In the short run, U.S. shale continues to dominate the headlines. But the uptick in interest in the offshore sector is a significant development. “[T]he steady oil price recovery since summer 2017 and renewed interest in growth opportunities has led to oil majors catching up in terms of exploration activity this year, both in the shale industry and offshore deepwater,” OPEC wrote in its February Oil Market Report.

Stay Informed

Subscribe to our newsletter today!

The Fuse is an energy news and analysis site supported by Securing America’s Future Energy. The views expressed here are those of individual contributors and do not necessarily represent the views of the organization.

Issues in Focus

Safety Standards for Crude-By-Rail Shipments

A series of accidents in North America in recent years have raised concerns regarding rail shipments of crude oil. Fatal accidents in Lynchburg, Virginia, Lac-Megantic, Quebec, Fayette County, West Virginia, and (most recently) Culbertson, Montana have prompted public outcry and regulatory scrutiny.

2014 saw an all-time record of 144 oil train incidents in the U.S.—up from just one in 2009—causing a total of more than $7 million in damage.

The spate of crude-by-rail accidents has emerged from the confluence of three factors. First is the massive increase in oil movements by rail, which has increased more than three-fold since 2010. Second is the inadequate safety features of DOT-111 cars, particularly those constructed prior to 2011, which account for roughly 70 percent of tank cars on U.S. railroads. Third is the high volatility of oil produced from the Bakken and other shale formations, which makes this crude more prone towards combustion.

Of these three, rail car safety standards is the factor over which regulators can exert the most control. After months of regulatory review, on May 1, 2015, the White House and the Department of Transportation unveiled the new safety standards. The announcement also coincided with new tank car standards in Canada—a critical move, since many crude by rail shipments cross the U.S.-Canadian border. In the words DOT, the new rule:

Since the rule was announced, Republicans in Congress sought to roll back the provision calling for an advanced breaking system, following concerns from the rail industry that such an upgrade would be unnecessary and could cost billions of dollars. The advanced braking systems are required to be in place by 2021.

Democrats in Congress have argued that the new rules are insufficient to mitigate the danger. Senator Maria Cantwell (D-WA) and Senator Tammy Baldwin (D-WI) both issued statements arguing that the rules were insufficient and the timelines for safety improvements were too long.

The current industry standard car, the CPC-1232, came into usage in October 2011. These cars have half inch thick shells (marginally thicker than the DOT-111 7/16 inch shells) and advanced valves that are more resilient in the event of an accident. However, these newer cars were involved in the derailments and explosions in Virginia and West Virginia within the past year, raising questions about the validity of replacing only the DOT-111s manufactured before 2011.

Before the rule was finalized, early reports indicated that the rule submitted to the White House by the Department of Transportation has proposed a two-stage phase-out of the current fleet of railcars, focusing first on the pre-2011 cars, then the current standard CPC-1232 cars. In the final rule, DOT mandated a more aggressive timeline for retrofitting the CPC-1232 cars, imposing a deadline of April 1, 2020 for non-jacketed cars.

Oops!

We weren't able to sign you up for our newsletter.Please check your email address and try again.

DataSpotlight

The recent oil production boom in the United States, while astounding, has created a misleading narrative that the United States is no longer dependent on oil imports. Reports of surging domestic production, calls for relaxation of the crude oil export ban, labels of “Saudi America,” and the recent collapse in oil prices have created a perception that the United States has more oil than it knows what to do with.

This view is misguided. While some forecasts project that the United States could become a self-sufficient oil producer within the next decade, this remains a distant prospect. According to the April 2015 Short Term Energy Outlook, total U.S. crude oil production averaged an estimated 9.3 million barrels per day in March, while total oil demand in the country is over 19 million barrels per day.

This graphic helps illustrate the regional variations in crude oil supply and demand. North America, Europe, and Asia all run significant production deficits, with the Middle East, Africa, Latin America, and Former Soviet Union are global engines of crude oil supply.